Electric power transmission and distribution systems or networks comprise high-voltage tie lines for connecting geographically separated regions, and substations for transforming voltages and for switching connections between lines. Power generation and load flow in a network with several substations is controlled by an energy management system. For managing the network, it is desirable to determine a state of the network, in particular load flows and stability margins. Measurements of average RMS (root mean square) values of voltages, currents, active power and reactive power flowing in the network and/or measurements of voltage and current phasors are made at various places in the network and collected by substation automation (SA) systems and by a system control and data acquisition (SCADA) system. The SA and SCADA systems further provide information about a status of network elements such as switchgear, compensation devices and variable transformers. The status of switchgear (i.e. circuit breakers, disconnectors, etc.) allows to infer the topology of the network, i.e. how the lines and devices are connected, and which lines, power generators and consumers are disconnected. Additionally, measurements of voltage and current phasors are made and collected. All the abovementioned measurements from throughout the network are collected at the energy management system, providing a snapshot of the state of the network. The snapshot allows to compute the state of the network, as described e.g. in “State estimation with phasor measurements”, Phadke et. al., IEEE Transactions on power systems, Vol. PWRS-1, No. 1, February 1996. There, all positive sequence bus voltages and some positive sequence currents are measured, the network topology is assumed to be known, and unknown voltages, phase angles and power flows are computed.